Available online at ScienceDirect. Energy Procedia 63 (2014 ) GHGT-12

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1 Available online at ScienceDirect Energy Procedia 63 (2014 ) GHGT-12 Costs of CO 2 capture technologies in coal fired power and hydrogen plants John Davison a *, Luca Mancuso b, Noemi Ferrari b a IEA Greenhouse Gas R&D Programme, Pure Offices, Cheltenham Office Park, Hatherley Lane, Cheltenham, GL51 6SH, U.K. b Foster Wheeler, Via Caboto 15, Corsico, Italy Abstract In recent years The International Energy Agency Greenhouse Gas R&D Programme (IEAGHG) has undertaken a series of studies on the performance and costs of coal-fired power and hydrogen plants with CO 2 capture, based on the three leading technology options. Following the significant technological advances and the substantial increase in estimated plant costs, IEAGHG has recently undertaken a wholly new study, covering the following plant types: Supercritical pulverised coal (SC-PC) power plant without CO 2 capture (reference); SC-PC power plant using oxy-combustion; SC-PC power plant with post-combustion capture based on a high-efficiency solvent washing process; Integrated Gasification Combined Cycle plant with pre-combustion capture using solvent scrubbing; Gasification for combined production of hydrogen (via PSA) and power. With the support of the leading technology suppliers, the study focuses on various process optimisation alternatives. Capital costs, levelised costs of electricity generation and costs of CO 2 emissions avoidance of the different power plant alternatives are estimated, including sensitivities to main financial parameters The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license 2013 The Authors. Published by Elsevier Ltd. ( Selection and peer-review under responsibility of GHGT. Peer-review under responsibility of the Organizing Committee of GHGT-12 Keywords: CCS, LCOE, power plant, hydrogen plant, SCPC, Oxycombustion, IGCC * Corresponding author. Tel.: +44 (0) address: john.davison@ieaghg.org The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license ( Peer-review under responsibility of the Organizing Committee of GHGT-12 doi: /j.egypro

2 John Davison et al. / Energy Procedia 63 ( 2014 ) Introduction Emissions to the atmosphere of greenhouse gases, particularly CO 2 emissions from use of fossil fuels, will need to be reduced to avoid the risks of climate change. The sector which emits most CO 2 is power and heat generation, which accounts for 42% of global emissions [1]. CO 2 emissions from power generation can be reduced by increasing generation efficiency, use of lower-carbon fuels such as natural gas, use of renewable energy (wind, solar, hydro etc.) and nuclear energy and by Carbon Capture and Storage (CCS). CCS can be applied to coal, gas, oil and biomass based power plants. This paper concentrates on coal based power plants, which account for 75% of global CO 2 emissions from power generation [1]. IEA has contracted Foster Wheeler to undertake a study to provide an up-to-date assessment of the performance and costs of coal-based power generation and hydrogen production plants based on the three leading CO 2 capture technologies, i.e. post combustion, oxy-combustion and pre-combustion capture [2]. The study, which is summarised in this paper, provides a baseline for possible subsequent studies on other capture processes, CCS in industries other than power and hydrogen generation and costs of CCS in other countries. It should be noted that the focus of this paper is to provide an up-to-date technical and economic assessment of coal-fired power and hydrogen plants with CCS. The study does not aim to provide a definitive comparison of different technologies or technology suppliers because such comparisons are strongly influenced by specific local constraints and by market factors, which can be subject to rapid changes. 2. Plant description 2.1. Power plants This paper assesses the design, performance and costs of the following coal based power generation plants. Supercritical pulverised coal power plant without CO 2 capture (reference plant); Supercritical pulverised coal power plant with post combustion capture based on CANSOLV solvent scrubbing; Supercritical pulverised coal power plant using oxy-combustion; IGCC plant based on GE slurry feed oxygen blown gasification and pre-combustion capture using Selexol solvent scrubbing; IGCC plant based on Shell dry feed oxygen blown gasification and pre-combustion capture using Selexol solvent scrubbing; IGCC plant based on MHI dry feed air blown gasification and pre-combustion capture using Selexol solvent scrubbing. The pulverised coal plant without capture is based on a single boiler, a net output of around 1000MW e and stateof-the-art steam conditions (27MPa, 600/620C) as used in new large coal fired power plants in Europe and Japan. The pulverised coal plants with post combustion and oxy-combustion capture have the same coal feed rate but lower net power outputs of MW e due to the energy consumption for capture. The coal feed rate of the IGCC plants is determined by the fuel feed rate of the two gas turbines, which are state of the art 50Hz F-class turbines suitable for high hydrogen content gas. The net power outputs of the IGCC plants are in the range of MW e, i.e. similar to the pulverised coal plants with capture Hydrogen plants Coal gasification plants with CCS could also produce hydrogen, which can be used as a carbon-free fuel for separate power plants, CHP plants and distributed energy consumers. Intermediate storage of hydrogen, such as in underground salt caverns, could be included to accommodate variations in end-user demand. This could potentially be an attractive option for decarbonisation of power plants operating at lower capacity factors, which are needed to accommodate the variability of power demand and variable renewable power generation technologies.

3 7600 John Davison et al. / Energy Procedia 63 ( 2014 ) This paper includes an assessment of three coal gasification hydrogen production plants with CCS, all based on GE oxygen blown gasification and Selexol solvent scrubbing: Plant with high net electricity co-production, including two 130MW e E class gas turbines; Plant with intermediate net electricity co-production, including two 77MW e F class gas turbines; Plant with low electricity co-production, including a PSA off-gas fired boiler Sensitivities All of the baseline power and hydrogen plants are based on 90% CO 2 capture. This is expected to be adequate for early CCS plants but in the longer term, when emission limits will be tighter, the emissions of the residual noncaptured CO 2 may necessitate tighter emission controls in other sectors such as transport and agriculture, which may involve high greenhouse gas abatement costs. This paper assesses the technical feasibility and costs of achieving a higher level of CO 2 capture (around 98%) in oxy-combustion and IGCC plants. In the oxy-combustion case this was achieved by passing the vent gas from CO 2 purification through a membrane separation unit, which produces a vent gas with a lower CO 2 concentration and a gas with higher concentrations of CO 2 and O 2, which is recycled to the boiler. For gasification based plants an additional MDEA solvent scrubbing stage was added after the Selexol scrubber. An alternative way of achieving near-zero net emissions of CO 2 is to co-fire some biomass, assuming that biomass which is produced in a sustainable way has near-zero net emissions of CO 2. Biomass could be used in post, pre and oxy-combustion capture plants. This paper assesses a plant with 90% post combustion capture and sufficient co-firing of woody biomass to achieve zero net emissions. Another possible constraint on the large scale application of CCS in some places may be water availability. To complement the base cases, which were based on natural draught cooling towers, sensitivity cases based on oncethrough sea water cooling and dry air cooling are presented. In addition to the sensitivities to percentage CO 2 avoidance and the type of cooling system, the paper also assesses the sensitivities to various economic parameters, including the coal price, capacity factor, discount rate, plant life, CO 2 transport and storage cost and CO 2 emissions cost. 3. Technical and economic basis The technical and economic basis for the assessment is described in more detail in reference 2. The main base case assumptions are: Greenfield site, Netherlands coastal location 9 C ambient temperature Natural draught cooling towers Eastern Australian internationally traded bituminous coal (0.86% sulphur a.r.) Coal price: 2.5/GJ LHV basis 2Q 2013 costs Discount rate: 8% (constant money values) Operating life: 25 years Construction time: Pulverised coal plants: 3 years, Gasification plants: 4 years Capacity factor: Pulverised coal plants: 90%, Gasification plants: 85% CO 2 transport and storage cost: 10/t stored 4. Cost definitions The cost estimates in this paper were derived in general accordance with the White Paper Toward a common method of cost estimation for CO 2 capture and storage at fossil fuel power plants, produced collaboratively by

4 John Davison et al. / Energy Procedia 63 ( 2014 ) authors from IEAGHG, EPRI, USDOE/NETL, Carnegie Mellon University, IEA, the Global CCS Institute and Vattenfall [3] Capital cost The capital cost is presented as the Total Plant Cost (TPC) and the Total Capital Requirement (TCR). TPC is defined as the installed cost of the plant, including direct materials, construction, EPC services, other costs and project contingency. TCR is defined as the sum of Total Plant Cost (TPC), interest during construction, spare parts cost, working capital, start-up costs and owner s costs. For each of the cases the TPC has been determined through a combination of licensor/vendor quotes, the use of Foster Wheeler s in-house database and the development of conceptual estimating models, based on the specific characteristics, materials and design conditions of each item of equipment in the plant. The other components of the TCR have been estimated mainly as percentages of other cost estimates in the plant. The overall estimate accuracy is in the range of +35/-15% Levelised cost of electricity Levelised Cost of Electricity (LCOE) is widely recognised as a convenient tool for comparing the unit costs of different technologies over their economic lifetime. LCOE is defined as the price of electricity which enables the present value from all sales of electricity over the economic lifetime of the plant to equal the present value of all costs of building, maintaining and operating the plant over its lifetime. LCOE in this paper is calculated assuming constant (in real terms) prices for fuel and other costs and constant operating capacity factors throughout the plant lifetime, apart from lower capacity factors in the first two years of operation. The Levelised Cost of Hydrogen (LCOH) is calculated in the same way except that it is necessary to take into account the revenue from the sale of electricity co-product. It was assumed that the value of the electricity coproduct is the cost of production in the IGCC plant that uses the same gasification and CO 2 capture technology as the hydrogen production plants, i.e. the GE gasification plant. If the lowest cost CCS power generation technology had been used to value the electricity output, the LCOH would have been higher Cost of CO 2 avoidance Costs of CO 2 avoidance were calculated by comparing the CO 2 emissions per kwh and the levelised costs of electricity of plants with capture and a reference plant without capture. Where: CAC is expressed in Euro per tonne of CO 2 LCOE is expressed in Euro per MWh CO 2 emission is expressed in tonnes of CO 2 per MWh (1) A pulverised coal plant without capture was used as the reference plant in all cases because the current power plant market indicates that this would in most cases be the preferred technology for coal fired plants without capture. The cost of CO 2 avoidance would be different if an alternative reference plant was used, for example an IGCC or a gas fired plant without capture.

5 7602 John Davison et al. / Energy Procedia 63 ( 2014 ) Results 5.1. Power plants performance A summary of the performance of the baseline power plants with and without capture is given in Table 1. Table 1 Power plant performance summary, pulverised coal plants Net power output CO 2 captured CO 2 emissions Efficiency HHV LHV Efficiency penalty for capture (LHV) MW kg/mwh kg/mwh % % % points Pulverised coal No capture (reference plant) Post combustion capture Oxy-combustion IGCC Shell, oxygen-blown GE, oxygen-blown MHI, air-blown The efficiencies and CO 2 emissions of the plants with capture are all broadly similar and the difference between the highest and lowest efficiency is less than 1 percentage point. Future technology improvements, such as development of improved CO 2 capture solvents, gas turbines and air separation units, could change the relative efficiencies of the processes. The efficiency penalties for oxy-combustion and post combustion capture are towards the bottom of the range in published data [4], demonstrating the improvements in capture technologies and thermal integration. Most published studies compare the efficiencies of IGCC plants with capture against IGCC plants without capture, so the efficiency penalties are not comparable to those in this paper, in which IGCC with capture is compared against a pulverised case reference plant. However, the average efficiency of IGCCs with capture in this paper is similar that of published studies [4]. CO 2 capture almost eliminates SOx emissions and also reduces NOx emissions, except for the post combustion capture case which has specific emissions about 25% higher than the reference plant, due to the lower thermal efficiency Capital cost The capital costs of the plants are summarised in Table 2 and breakdowns of the total plant costs are given in Figures 1 and 2. Table 2 Capital costs of electricity generation plants Total Plant Cost (TPC) Total Capital Requirement (TCR) TPC increase compared to the reference plant /kw /kw % Pulverised coal plants No capture (reference plant) Post combustion capture Oxy-combustion IGCC plants Shell oxygen-blown GE oxygen-blown MHI air-blown

6 John Davison et al. / Energy Procedia 63 ( 2014 ) Figure 1 Specific Total Plant Cost of pulverised coal plants Figure 2 Specific Total Plant Cost of IGCC plants Including capture increases the specific cost per kw e by 91% for the pulverised coal cases and % for the IGCC cases, compared to the pulverised coal reference plant. This cost increase is partly due to the cost of additional plant required for capture and partly due to the reduced net power output per unit of thermal capacity, e.g. boiler size. There is no significant difference between the specific capital costs of the post combustion capture (PCC) and oxycombustion plants. The main cost of additional plant for oxy-combustion is the cost of the Air Separation Unit (ASU). The cost of the CO 2 compression unit is higher in the oxy-combustion plant than in the post combustion plant because the volume of gas to be compressed is greater, due to the presence of impurities, and due to the cost of the CO 2 Processing Unit (CPU) which removes the impurities. The CPU is included in the CO 2 compression unit cost in Figure 2, although it could also be considered to be a type of CO 2 capture unit. The specific capital costs of the three IGCC cases are similar. The MHI air blown gasifier plant has higher costs for gasification, syngas treating and acid gas removal (AGR), which is to be expected due to the higher volume of the fuel gas but it avoids the cost of a large ASU (the MHI gasifier plant includes a small ASU which provides nitrogen for coal feeding but the vendor included this in the cost of the gasification unit) Levelised costs of electricity and CO 2 avoidance cost Levelised costs of electricity (LCOE) and CO 2 avoidance cost (CAC) are shown in Table 3 and Figure 3. The costs of the IGCC plants are higher than those of the pulverised coal combustion plants, mainly because of higher capital costs and higher fixed operating and maintenance (O+M) costs, particularly maintenance costs.

7 7604 John Davison et al. / Energy Procedia 63 ( 2014 ) Table 3 Levelised cost of electricity and CO 2 avoidance cost Levelised Cost of Electricity (LCOE) CO 2 Avoidance Cost (CAC) /MWh % increase compared to the reference plant /tonne Pulverised coal plants No capture (reference plant) 52.0 Post combustion capture Oxy-combustion IGCC plants Shell oxygen-blown GE oxygen-blown MHI air-blown Figure 3 Levelised Costs of Electricity 6. Hydrogen co-production plants A summary of the performance of the baseline hydrogen/power co-production plants is given in Table 4. The Net efficiency to hydrogen in Table 4 is calculated by assuming that the net power output displaces electricity generated by a GE gasification IGCC plant with CO 2 capture. It should be noted that while the efficiencies of coal fired power plants are higher on an LHV basis than on an HHV basis, hydrogen plants have a significantly higher efficiency on an HHV basis. Table 4 Hydrogen plant performance summary Hydrogen output Net power output Efficiency to hydrogen Efficiency to net power Net efficiency to hydrogen LHV LHV HHV LHV MW MW % % % % High electricity Medium electricity Low electricity Capital costs and levelised costs of hydrogen (LCOH) are shown in Table 5. For the calculation of LCOH, the electricity co-product is valued at /MWh, i.e. the production cost of the corresponding IGCC case (GE gasifier). Similarly, the capital cost associated with electricity production in the IGCC plant is subtracted from the capital cost of the co-production plants to give the specific capital cost of hydrogen production. The highest efficiency and lowest cost of hydrogen production are achieved by the plant with the lowest amount of electricity coproduction, which is based on feeding the PSA off-gas to an on-site boiler.

8 John Davison et al. / Energy Procedia 63 ( 2014 ) Table 5 Costs of hydrogen plants Total Plant Cost (TPC) Levelised Cost of Hydrogen (LCOH) HHV HHV LHV /kw H net /GJ /GJ High electricity co-production Medium electricity co-production Low electricity co-production Plant design sensitivity cases 7.1. Near-zero emission plants The performance and costs of the plants with near-zero emissions are summarised in Table 6, which also shows the change in efficiencies and costs compared to plants with 90% capture. Increasing the percentage CO 2 abatement reduces the efficiency and increases the capital cost and LCOE. The largest increase in LCOE is for the biomass cofiring case and the lowest is for the oxy-combustion case. The CO 2 abatement costs per tonne are lower for the nearzero emission cases than for 90% capture. In the case of oxy-combustion this is because the vent gas from the CO 2 purification unit has a relatively high CO 2 concentration (25%mol). In the case of IGCC, the reasons for the cost reduction are more complex. The cost of CO 2 abatement comprises the cost of cost of capture (shift conversion, CO 2 separation etc.) and the higher cost of the core IGCC process without capture compared to a pulverised coal plant without capture. Although the cost of capturing each extra tonne of CO 2 may be higher in the near-zero emissions case than in the 90% capture case, the extra costs for the core IGCC units compared to a pulverised coal plant remain the same. This cost is spread over a greater number of tonnes of CO 2 captured, resulting in a lower specific cost. Table 6 Near-zero emission plants PCC+biomass (100% abatement) Oxy-combustion (97.6% capture) IGCC (98.6% capture) Efficiency TPC LCOE CAC % % pt. change /kw /kw change /MWh /MWh change /t /t change It should be noted that biomass could also be used in oxy-combustion and IGCC plants and greater proportions of biomass could be used, thereby achieving negative emissions. However, availability of biomass fuel may be limited due to competition with other land uses such as food production and natural habitats. Also, biomass may have a higher value for abatement of CO 2 emissions in other sectors where other low-co 2 options are more limited, such as production of biofuels for transport. This assessment has shown that even if biomass availability is a constraint, CCS plants would be able to achieve near-zero emissions if required without increasing the specific cost of CO 2 abatement Cooling system sensitivity Alternative cooling systems can be used to reduce the net water requirement of power plants with CCS to near zero in the case of oxy-combustion and post combustion capture and by around 70% in the case of IGCC. For the ambient conditions considered in this assessment, using once-though seawater cooling instead of natural draught cooling towers increases the thermal efficiency of plants with CCS by up to 0.7 percentage points and using air cooling reduces the efficiencies by up to 0.7 percentage points and both of these cooling systems have little impact

9 7606 John Davison et al. / Energy Procedia 63 ( 2014 ) on the capital cost. However, at higher ambient temperatures the impact of air cooling is expected to be more negative. 8. Economic sensitivity The costs of CCS depend on economic parameters which will vary over time and between different plant locations. It is therefore important therefore to consider the sensitivity of costs to variations in the parameters. The sensitivity to the coal price, economic discount rate, plant life, cost of CO 2 transport and storage, operating capacity factor and cost penalty for non-captured CO 2 emissions. Sensitivities were assessed for all of the main study cases and the results for each parameter are presented in reference 2. As an example, the sensitivities to all of the parameters are shown in Figure 4 for the pulverised coal plant with post combustion capture. The results would be similar for the oxy-combustion plant. Figure 4 Sensitivities of Levelised Cost of Electricity (plant with post combustion capture) Coal price can vary over a wide range due to local coal availability and mining costs to market variability, which is difficult to predict. Varying the coal price by ±1.5 /GJ from the base case of 2.5 /GJ changes the LCOE by ±15.5 /MWh. The operating capacity factor of the plant may be lower than the 90% base case assumption in this paper, either because of poor reliability and availability of the plant or because of electricity system constraints, i.e. other power generators with lower marginal operating costs being operated in preference to CCS plants at times of low power demand. Reducing the capacity factor can have a substantial effect of the LCOE, Figure 4 shows that reducing the capacity factor from 90% to 70% would increase the LCOE by 15.6 /MWh. If the plant operates at a low capacity factor because of electricity system constraints the impacts on plant profitability and rate of return may be much less significant because the times when the plants are forced to not operate would by definition be times of low electricity prices, so the impacts on net revenues and rates of return of not operating at such times may be small. However, this is difficult to assess because the electricity prices depend on the costs of the other generating plants in the overall electricity system. Costs of CO 2 transport and storage are expected to vary considerably between different sites. At sites where CO 2 can be sold, for example for enhanced oil recovery, the net cost may be zero or even negative. If the CO 2 has to be transported a long distance in a relatively small pipeline for offshore storage the cost would be substantially greater than the 10 /t base case scenario in this paper. Sensitivities to costs in the range of zero to 20 /t of CO 2 stored are shown in Figure 4 but the range of costs may be higher in some circumstances. The main economic evaluation in this paper does not include a cost for emitting non-captured CO 2 to the atmosphere. Including a cost that is equal to the cost of CO 2 abatement by CCS in this plant, i.e. 65 /t CO 2, would increase the LCOE by 6 /MWh. The LCOE is relatively insensitive to increasing the plant life from 25 to 40 years, because of the effects of economic discounting. The sensitivities of CO 2 avoidance cost (CAC) to variations in the economic parameters are shown in Figure 5. It can be seen that variations in the CO 2 emission cost, which has relatively little impact on the LCOE of the plant with capture, has by far the largest impact on the CO 2 avoidance cost, because it has a large impact on the LCOE of the

10 John Davison et al. / Energy Procedia 63 ( 2014 ) reference plant. Conversely, the coal price, which has a relatively large impact on the COE of the plant with capture has a relatively small impact on the avoidance cost, because it has broadly similar impacts on both plants, the only difference being due to the lower efficiency of the plant with capture. Apart from the emissions cost, the parameter which has the greatest impact on the avoidance cost, for the ranges considered in this study, is the CO 2 transport and storage cost. 9. Conclusions Figure 5 Sensitivities of CO 2 avoidance cost (plant with post combustion capture) The thermal efficiencies of power plants with CCS based on pulverised coal combustion with post combustion capture, oxy-combustion and IGCC with pre-combustion capture are % LHV basis, which is around 9 percentage points lower than a reference pulverised coal plant without capture. The levelised cost of base load electricity generation is about 92 /MWh for boiler-based plants with oxycombustion or post combustion capture and 115 /MWh for IGCC plants with pre-combustion capture. This is about % higher than the reference pulverised coal plant without CCS. Costs of CO2 emission avoidance compared to the reference plant are /t for boiler based plants with CCS and /t for IGCC plants. Increasing the rate of CO2 capture to 98% in oxy-combustion and IGCC plants would increase the cost of electricity by 3-5% but reduce the cost per tonne of CO2 emissions avoided by 3%. Co-firing biomass can be used to reduce net CO2 emissions of plants with CCS to zero, assuming biomass is regarded as a zero CO2 fuel. In a plant with post combustion capture this increases the cost of electricity by 6% and has no impact on the cost of CO2 avoidance, but the cost depends strongly on the cost of biomass, which depends on the availability. The net efficiency of producing hydrogen by coal gasification with CCS is 57.8% on an LHV basis (65.5% HHV basis) and the levelised cost of hydrogen is 16.1 /GJ LHV basis (13.6 /GJ HHV). Alternative cooling systems could be used to reduce the water requirements of pulverised coal power plants with CCS to close to zero. The reduction would around 70% for IGCC. For the ambient conditions of this assessment, using sea-water cooling instead of cooling towers increases the thermal efficiency by a maximum of 0.7 percentage points and using air cooling reduces the efficiency by a maximum of 0.7 percentage points and both of these cooling systems have little impact on the capital cost. However, at higher ambient temperatures the impact of air cooling is expected to be more negative. References [1] IEA, CO 2 emissions from fuel combustion, highlights, 2013 Edition. International Energy Agency, Paris, France, [2] IEAGHG, CO 2 capture at coal based power and hydrogen plants, Report 2014/3, May 2014, IEAGHG, Cheltenham, UK, [3] IEAGHG, Toward a common method of cost estimation for CO 2 capture and storage at fossil fuel power plants. IEAGHG report 2013/TR2, March 2013, IEAGHG, Cheltenham, UK, [4] Finkenrath, M., Cost and performance of carbon dioxide capture from power generation. International Energy Agency, Paris, France